System, method, and apparatus for multi-stage completion

ABSTRACT

Systems and methods for completing a well, involving a fracture placement packer assembly comprising an inflatable packer positioned on an uphole side of the assembly; the inflatable packer is structured to execute repeated inflation/deflation cycles in response to an inflation/deflation procedure, and wherein the inflatable packer is a self-anchoring packer; and the fracture placement packer assembly is structured to be couplable to a conveyance device.

BACKGROUND

The statements in this section merely provide background informationrelated to the present disclosure and may not constitute prior art.

The technical field generally, but not exclusively, relates tocompleting multiple fracturing stages in a wellbore. Presently knownmulti-stage fracturing techniques include a “plug and perf” operation(e.g. using bridge plugs between stages) and using an open hole packerwith sliding sleeves. Presently known multi-stage fracturing techniquessuffer from one or more drawbacks, with examples including: difficultyin controlling fracture placement; long cycle times between stages, e.g.to run tools into the hole; limitations on treatment execution such asthe order of treating several intervals of a subterranean formationsuccessively; and/or low reliability systems with intricate movingmechanical parts.

SUMMARY

In some embodiments, there are provided methods, comprising positioninga fracture placement packer assembly, comprising an inflatable packerpositioned on an uphole side of the assembly, in a wellbore at afracture treatment position; inflating the inflatable packer; fracturetreating an interval of a subtteranean formation operationally coupledto the wellbore; and the methods further comprising at least oneoperation selected from the operations consisting of: marking theinterval before the fracture treating; wherein the inflating the packerfurther comprises inflating a self-anchoring packer; fracture treating asecond interval after the first interval, wherein the second intervalcomprises a greater measured depth than the first interval; fracturetreating a second interval after the first interval, wherein the secondinterval comprises a smaller measured depth than the first interval, themethod further including positioning a sand plug across the firstinterval before the fracture treating the second interval; fracturetreating a second interval after the first interval, wherein the secondinterval comprises a smaller measured depth than the first interval, themethod further including positioning a sand plug across the firstinterval before the fracture treating the second interval, wherein thesand plug comprises a high particulate fraction fluid having a pluralityof particle size modalities therein; fracture treating a second intervalafter the first interval, wherein the second interval comprises asmaller measured depth than the first interval, the method furtherincluding positioning a sand plug across the first interval before thefracture treating the second interval, wherein the sand plug comprises ahigh particulate fraction fluid having a plurality of particle sizemodalities therein, and removing an amount of water from the sand plug;performing the fracture treating with a drill string positioned in thewellbore; performing the fracture treating with an uncemented casingstring positioned in the wellbore; interpreting at least one of pressureinformation, temperature information, and inflation information,determining a wear value for the assembly in response to theinformation, and providing the wear value to an output device; whereinthe marking comprises oriented marking; wherein the marking comprises aselected geometric configuration; wherein the marking comprises at leastone operation selected from scoring, punching, perforating,pre-inflating the packer, gouging, grooving, and indenting; wherein theinflating comprises an operation selected from the operations consistingof providing a pressure pulse, dropping a ball, and providing anelectrical signal; providing a liner in the wellbore, positioning anumber of external packers between the liner and a wellbore face,wherein each of the external packers comprises an activatable packer,activating the external packers, and wherein the inflating theinflatable packer comprises running the inflatable packer to a selectedposition within the liner before the inflating; the method having the“providing a liner” operation, wherein the selected position comprises aposition aligning the inflatable packer with one of the externalpackers; and the method having the “providing a liner” operation,wherein the activating the external packers comprises at least oneoperation selected from inflating the external packers, swelling theexternal packers, and mechanically activating the external packers.

Embodiments relate to systems, comprising: a fracture placement packerassembly comprising an inflatable packer positioned on an uphole side ofthe assembly; wherein the inflatable packer is structured to executerepeated inflation/deflation cycles in response to aninflation/deflation procedure, and wherein the inflatable packer is aself-anchoring packer; and wherein the fracture placement packerassembly is structured to be couplable to a conveyance device.

Embodiments aim at systems, comprising: a straddle packer assemblycomprising a first inflatable packer positioned on an uphole side of theassembly and a second inflatable packer positioned on a down hole sideof the assembly; wherein each of the inflatable packers are structuredto execute repeated inflation/deflation cycles in response to aninflation/deflation procedure; wherein the fracture placement packerassembly is structured to be couplable to a conveyance device; andwherein the straddle packer assembly comprises a spacer elementpositioned between the first and second inflatable packers, the spacerelement including a fluid conductance feature and the spacer elementstructured to maintain the inflatable packers at a specified distance.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 shows a straddle packer assembly with multiple inflatablepackers.

FIG. 2 shows a positioned assembly in a wellbore.

FIG. 3 shows operations to fracture multiple zones using straddlepackers.

FIG. 4 shows open hole completion systems using a packer.

FIG. 5 shows a straddle packer assembly operating in a wellbore having acemented casing therein.

FIG. 6 shows a straddle packer assembly operating in a wellbore havingan uncemented liner positioned therein across an interval of interest.

FIG. 7A illustrates a particle pack from the prior art.

FIG. 7B is a magnification of the pack illustrated in 7A.

FIG. 8A illustrates a particle pack as in the present disclosure.

FIG. 8B is a magnification of the pack illustrated in 8A.

DETAILED DESCRIPTION OF SOME ILLUSTRATIVE EMBODIMENTS

For the purposes of promoting an understanding of the principles of thedisclosure, reference will now be made to the embodiments illustrated inthe drawings and specific language will be used to describe the same. Itwill nevertheless be understood that no limitation of the scope of theclaimed subject matter is thereby intended, any alterations and furthermodifications in the illustrated embodiments, and any furtherapplications of the principles of the application as illustrated thereinas would normally occur to one skilled in the art to which thedisclosure relates are contemplated herein.

At the outset, it should be noted that in the development of any suchactual embodiment, numerous implementation-specific decisions must bemade to achieve the developer's specific goals, such as compliance withsystem related and business related constraints, which will vary fromone implementation to another. Moreover, it will be appreciated thatsuch a development effort might be complex and time consuming but wouldnevertheless be a routine undertaking for those of ordinary skill in theart having the benefit of this disclosure. In addition, the compositionused/disclosed herein can also comprise some components other than thosecited. In the summary and this detailed description, each numericalvalue should be read once as modified by the term “about” (unlessalready expressly so modified), and then read again as not so modifiedunless otherwise indicated in context. Also, in the summary and thisdetailed description, it should be understood that a concentration rangelisted or described as being useful, suitable, or the like, is intendedthat any and every concentration within the range, including the endpoints, is to be considered as having been stated. For example, “a rangeof from 1 to 10” is to be read as indicating each and every possiblenumber along the continuum between about 1 and about 10. Thus, even ifspecific data points within the range, or even no data points within therange, are explicitly identified or refer to only a few specific, it isto be understood that the Applicant appreciate and understands that anyand all data points within the range are to be considered to have beenspecified, and that the Applicant possessed knowledge of the entirerange and all points within the range.

Referencing FIG. 1, a straddle packer assembly 100 includes a firstinflatable packer 102 positioned on an uphole side of the assembly 100,and a second inflatable packer 104 positioned on a downhole side of theassembly. Uphole and downhole, as utilized herein, refer to the measureddepth of the wellbore, or to the intended orientation of the assembly100, for example when assembled at a surface location and not in awellbore. Uphole is the side at a smaller measured depth, or closer tothe wellhead, and down hole is the side at a greater measured depth, orfurther from the wellhead.

In embodiments, the assembly 100 further includes each of the inflatablepackers able to repeatedly execute an inflation/deflation cycle. Themechanics of the inflatable packers may be of any type, for exampleinflated or deflated by pressurized fluid pumped into the wellboreaccording to the positions of one or more sleeves, sliding elements,control valves, etc. The actuation of any moving parts of the inflatablepackers may be electrical, pressure pulse activated, mechanical,actuated by a dropped ball pumped through a receiving device, or by anyother actuation method. The specific operations of the inflatablepackers are not limiting and are not further described herein.

The number of inflation/deflation cycles that is sufficient to be ableto be repeatedly executed is dependent upon the specific application andwill be known to one of skill in the art having the benefit of thedisclosures herein. Certain numbers of operational cycles that meet therepeatedly executed criterion include, without limitation, include atleast enough inflation/deflation cycles to complete two fracturetreatments within a wellbore; at least enough inflation/deflation cyclesto complete a nominal number of fracture treatments within a wellbore;at least enough inflation/deflation cycles to complete all contemplatedfracture treatments within a wellbore; at least enoughinflation/deflation cycles to complete a nominal number of fracturetreatments for a specified number of wellbores; at least enoughinflation/deflation cycles to complete all contemplated fracturetreatments within a specified number of wellbores; and at least enoughinflation/deflation cycles to provide an operating service life of theinflatable packers to provide an acceptable return on investment of thecost of the inflatable packers.

In embodiments, the assembly 100 further includes a spacer element 106positioned between the packers 102, 104. The spacer element 106 includesa fluid conductance feature 110, and the spacer element 106 maintainsthe inflatable packers 102, 104 at a specified distance. Example andnon-limiting fluid conductance features 110 include holes, ports, gaps,slots, or other features in the spacer element 106 to allow flow offracturing fluids therethrough. An example fluid conductance feature 110includes ports that open in response to a sliding sleeve, providing afluid conductance feature 110 that is selectively opened.

The specified distance 108 is any distance desired that encompasses thedesired fracturing zone. Example and non-limiting distances include atleast about 10 feet, between about 10 feet and 30 feet (e.g. a standardtubular length), between about 30 feet and 90 feet (e.g. between one andthree standard tubular lengths), and/or any distance up to about 1,000feet. A short fracturing zone allows for precise placement of thefracturing treatment, but can run some risk of the fracture growing pastone of the inflatable packers 102, 104 within the wellbore, which couldrun the risk of causing the assembly 100 to get stuck. Also, a shortfracturing zone requires a greater number of fracturing treatments tostimulate a longer formation segment.

A long fracturing zone causes greater uncertainty in the placement ofthe fracturing treatment, can require high pumping rates for anacceptable fracture placement and geometry, and can induce multiplesimultaneous fractures to occur (which may be a desired or undesiredresponse). However, a long fracturing zone allows for the stimulation ofa longer formation segment with fewer treatments. The long fracturingzone may also reduce the risk of a fracture growing past one of theinflatable packers 102, 104, depending upon the nature of the formationand the stress and natural fracturing profile therein. It is amechanical step for one of skill in the art, having the benefit of thedisclosures herein and contemplating information that is generallyavailable for a particular formation, treating fluids available, andtreating equipment available, to select a specified distance value for aparticular application of the assembly 100.

In some embodiments, the assembly 100 is couplable to a conveyancedevice 112, and in the example of FIG. 1 is depicted as coupled to theconveyance device 112. Example and non-limiting conveyance devices 112include a coiled tubing unit, a wellbore tubular, a wellbore casing,and/or a drill string. In certain embodiments, the spacer element 106 isincluded as a portion of the conveyance device 112, and/or as a modifiedportion of the conveyance device 112. For example, the spacer element106 may be included as a modified tubular in a tubing string.

In certain embodiments, a system including the assembly 100 includes awellbore marking tool. The wellbore marking tool is a tool structured tomark a fracture entry position of the wellbore, and can include anyaspect of the wellbore, including at least a formation face 204 (e.g.see FIG. 2), a casing wall (cemented or uncemented), and/or a linerwall. The marking of the fracture entry position includes perforating,punching, scraping, scoring, grooving, and/or indenting the fractureentry position. Example and non-limiting wellbore marking tools includea rotary tool, a star shaped rotary tool, a scraping device, a fluidjetting device, an abrasive jetting device, a punching device, and/orany other device that is capable of marking the wellbore to provide fora preferential fluid entry or pressure failure point in the wellboresuch that the fracture treatment is more likely to initiate at themarked position.

In certain embodiments, the wellbore marking tool is an oriented tool inthe wellbore, such that the provided marks are oriented in a selectedmanner. An example orientation includes an orientation selected toreduce tortuosity of the fracture entry from the wellbore zone into theformation zone. The orientation may be azimuthal (e.g. azimuth of theplane perpendicular to the wellbore), for example when the wellbore isinclined relative to the formation (due to incline of the wellbore, theformation, or both). Additionally or alternatively, the orientation maybe axial (e.g. a mark on one side of a wellbore is at a differentialmeasured depth from an opposing mark on the other side of the wellbore),for example when the wellbore is angled on the horizontal plane at anoffset from the highest in-situ stress. The provided examples oforienting the wellbore marking tool are non-limiting.

Referencing FIG. 2, a positioned assembly 200 is depicted in a wellboreat a formation of interest 202, which may comprise one or more intervalsof interest. The wellbore segment depicted is horizontal in the example,although the wellbore may be vertical, deviated, highly deviated, orhorizontal. The assembly is positioned within an uncemented liner 208. Anumber of external packers 206 are provided outside the liner 208, whichmay center the liner 208, prevent movement of the liner 208 duringtreatment operations, and/or provide zonal isolation of the interval 202during treatment operations. The external packers 206 may be of anytype, including at least inflatable packers, swellable packers, and/ormechanically operated packers. The first inflatable packer 102 ispositioned at one of the external packers 206, and the second inflatablepacker 104 is positioned at a second one of the external packers 206.

The positioning of the inflatable packers 102, 104 at the locations ofthe external packers 206 provides for more positive zonal isolation, andprovides for a better stress profile for the liner when all packers andengaged and during treatment operations. However, the positioning of theinflatable packers 102, 104 at the locations of the external packers 206is optional and non-limiting. The liner 208 may include ports, gaps,holes, or other features to allow passage of fracturing fluidtherethrough. Additionally or alternatively, a wellbore marking tool maybe utilized on the liner 208 to provide fluid passages therethrough orto provide a failure zone that will open upon during fracturingtreatment operations.

Referencing FIG. 3, an operation to fracture multiple zones is depictedschematically. The operation 300 includes operating a star wheelmechanical punch throughout a wellbore zone to be treated. The wellboredepicted in FIG. 3 is an open hole completion. The operation 302illustrates a straddle packer assembly being utilized to treat thewellbore in a toe-to-heel operation, fracturing zones from a highermeasured depth value to a lower measured depth value. The operation 304illustrates the straddle packer assembly being utilized to treat thewellbore in a heel-to-toe operation, fracturing zones from a lowermeasured depth value to a higher measured depth value. The wellbore maybe fractured in any order, as the straddle packer assembly provides forzonal isolation wherever positioned.

The wellbore depicted in FIG. 4 is an open hole completion. Theoperation 400 includes operating a star wheel mechanical punchthroughout a wellbore zone to be treated. The operation 402 illustratesa fracture placement packer assembly being utilized to treat thewellbore in a toe-to-heel operation. The fracture placement packerassembly includes an inflatable packer positioned on an uphole side ofthe assembly. The inflatable packer is designed to execute repeatedinflation/deflation cycles. Unlike the opposing inflatable packers ofthe straddle packer assembly, the fracturing pressure provides a netuphole force onto the conveyance device and the fracture placementpacker assembly. Accordingly, in certain embodiments, the inflatablepacker of the fracture placement packer assembly is a self-anchoringpacker. In certain embodiments, the inflatable packer of the fractureplacement packer assembly is not a self-anchoring packer. In certainembodiments, one or more inflatable packers of the straddle packerassembly are self-anchoring packers.

In the example of FIG. 4, zonal isolation is provided after eachfracture treatment by positioning a “sand plug”, which may be providedby utilizing any particulate laden fluid, across the previously treatedinterval, and the fracture placement packer assembly is positioned at aplace to treat the next zone of the interval (or the next interval).Particulate laden fluids allow settling of the particles therein overtime. In a vertical well, zone isolation can nevertheless be provided byadding enough fluid to account for settling. In a horizontal well, thesettling occurs along the length of the isolated zone, and additionalfluid will not assist in providing coverage for the settled areas.Additionally, a fluid loaded with a particulate material, such as aproppant, has a maximal packed volume fraction that provides for amaximum pressure drop through a pack of the fluid, even after settling.Again, in a vertical well, this is not a major limitation because theisolated zones below a treated zone, in addition to having a particlepack thereacross, are also generally at a higher fracturing stress thanvertically higher zones that are being treated, which assists inproviding zonal isolation. In a horizontal well, by contrast, anisolated zone is typically at the same or very similar fracturing stressto the next treated zone, and additionally already has induced fracturestherein providing for a reduced initiating stress. Accordingly,providing zonal isolation with a “sand plug” or particle pack is morechallenging in a horizontal or highly deviated wellbore.

Referencing FIG. 7, a previously known particle pack is provided forzonal isolation in a particular well segment. The particle pack issettled, providing for a head space 702 in the wellbore which will havea reduced isolation effectiveness. Additionally, in the expanded section704, it can be seen that natural void spaces are provided through theparticle pack, due to the natural packed volume fraction of theparticles. The more uniform the particle sizes the lower the naturalpacked volume fraction of the particles and the greater the void spaceswithin the pack. A high degree of particle size uniformity is desirablefor proppant materials utilized in fracturing treatments, which aretherefore the typically available materials for a particle packplacement.

Referencing FIG. 8, a particle pack consistent with the presentdisclosure is depicted. The particle pack of FIG. 8 includes a number ofparticle size modalities 802, 804, including at least two particle sizemodalities, although three, four, five, or more particle size modalitiesare possible. Particle packs including multiple size modalities can havemuch higher packed volume fractions than single-sized materials,including packed volume fractions exceeding 75%, 80%, 85%, 90% and evenexceeding 95% while still maintaining a fluidized material that can bepumped. Accordingly, head space from settled fluids are much lower in afluid having two or more size modality particles. Further, the settlingrate of fluids having two or more size modalities are much lower thansingle particle size fluids. In a single particle size fluid, thesettling rate is largely defined by the fluid viscosity and thedensities of the fluid and particles. While other characteristics, suchas the viscoelastic nature of a fluid, can reduce settling rates, asingle particle size fluid in a completely static particle pack willnevertheless settle out the particles in a short period of time. Fluidshaving high concentrations of two or more size modality particles canavoid particle settling for hours or days, even with very low carrierfluid viscosities. Accordingly, the particle pack of FIG. 8 has verylittle settling, and a much lower head space even after settling occurs.

Particle packs created from fluids having two or more size modalityparticles can re-fluidize with a very small amount of liquid. This canbe a desirable feature, for example when cleaning out the particle packsand returning a well to production. However, during zonal isolation there-fluidization of the particle pack may be undesirable. In certainembodiments, the particle pack is provided as a fluid having two or moresize modality particles and further including a water removalconstituent. Example and non-limiting water removal constituents includefibers (which may be hydroscopic, or may just provide support fromparticle movement occurring, similar to a proppant fracture flowbackprevention material), a hydroscopic material, and/or a water absorbentmaterial (e.g. bentonite, a polymer, etc.). Example and non-limitingmaterials include coated materials, for example a material that is notactive to absorb water until placed across the zone to be isolated, andin response to time, temperature, pressure, and/or a reaction thecoating is removed and water absorption or other removal commences.Additionally or alternatively, the water removal and/or particle packfixing material (e.g. fibers) will degrade at a later time, allowing theparticle pack to re-fluidize and enhance cleanup.

Referencing FIG. 5, a straddle packer assembly is depicted operating ina wellbore having a cemented casing therein. A mechanical marking toolsuch as a star-wheel punch is run through the zones of interest inoperation 500, puncturing the casing, and potentially scoring thecement. The straddle packer assembly is utilized in operation 502 tofracture an interval of the formation of interest from toe-to-heel, inoperation 504 to fracture an interval of the formation from heel-to-toe,or otherwise utilized to fracture an interval the formation in anyselected manner.

Referencing FIG. 6, a straddle packer assembly is depicted operating ina wellbore having an uncemented liner positioned therein across aninterval of interest. The liner is punched, scored, or perforated,although it also may not be, and the straddle packer assembly fracturesthe interval of interest from toe-to-heel in operation 600, or fracturesthe interval of interest from heel-to-toe in operation 602. Theinflatable packers of the straddle packer assembly are aligned withexternal packers in the illustration of FIG. 6, although in certainembodiments the external packers may not be present or may not bealigned with the inflatable packers of the straddle packer assembly.

The schematic flow descriptions which follow provide illustrativeembodiments of performing procedures for multi-stage completions in awellbore. Operations illustrated are understood to be examples only, andoperations may be combined or divided, and added or removed, as well asre-ordered in whole or part, unless stated explicitly to the contraryherein. Certain operations illustrated may be implemented by a computerexecuting a computer program product on a computer readable medium,where the computer program product comprises instructions causing thecomputer to execute one or more of the operations, or to issue commandsto other devices to execute one or more of the operations.

Certain operations described herein include operations to interpret oneor more parameters. Interpreting, as utilized herein, includes receivingvalues by any method known in the art, including at least receivingvalues from a datalink or network communication, receiving an electronicsignal (e.g. a voltage, frequency, current, or PWM signal) indicative ofthe value, receiving a software parameter indicative of the value,reading the value from a memory location on a computer readable medium,receiving the value as a run-time parameter by any means known in theart including operator entry, and/or by receiving a value by which theinterpreted parameter can be calculated, and/or by referencing a defaultvalue that is interpreted to be the parameter value.

An example procedure includes an operation to position a fractureplacement packer assembly, including an inflatable packer positioned onan uphole side of the assembly, in a wellbore at a fracture treatmentposition. The procedure includes an operation to inflate the inflatablepacker, and to fracture treat an interval of a formation operationallycoupled to the wellbore. In certain embodiments, the procedure includesan operation to mark the interval before the fracture treating, and/orto inflate the packer by inflating a self-anchoring packer. In certainembodiments, the procedure includes an operation to fracture treat asecond interval after the fracturing of the first interval, where thesecond interval is at a greater measured depth than the first interval.

In certain embodiments, the procedure includes an operation to fracturetreat a second interval after the fracturing of the first interval,where the second interval is at a smaller measured depth than the firstinterval, and an operation to position a particle pack or sand plugacross the first interval before the fracture treating the secondinterval. An example procedure further includes an operation to positionthe particle pack across the first interval by positioning a highparticulate fraction fluid, having a number of particle size modalitiesin the fluid, across the first interval. Certain further embodiments ofthe procedure include fixing the particle pack in place (e.g. withfibers), and/or removing an amount of liquid fluid (e.g. water) from theparticle pack. An example operation to remove an amount of liquid fluidfrom the particle pack includes placing a water removal constituent inthe high particulate fraction fluid.

In certain embodiments, the procedure includes an operation to fracturetreat an interval of a formation with a drill string positioned in thewellbore, and/or to perform the fracture treatment with an uncementedcasing string (and/or a liner) positioned in the wellbore. In certainembodiments, the procedure includes an operation to provide a liner inthe wellbore, to position a number of external packers between the linerand a wellbore face, where each of the external packers includes anactivatable packer, an operation to activate the external packers, andwhere the operation to inflate the inflatable packer includes runningthe inflatable packer to a selected position within the liner before theinflating. In certain embodiments, the selected position is a positionaligning the inflatable packer with an external packer. In certainembodiments, the operation to activate the external packers includesinflating the external packers, swelling the external packers, and/ormechanically activating the external packers.

In certain embodiments, the procedure includes an operation to interpretpressure information, temperature information, and/or inflationinformation, and to determine a wear value for the assembly in responseto the information. The determining the wear value may be according toassembly wear modeling, experience in similar operational settings,and/or according to manufacturer wear information. The procedure furtherincludes an operation to provide the wear value to an output device, forexample a monitoring screen, a report, a maintenance system, a datalinkor network, and/or to store the value on a computer readable medium innon-transitory memory.

In certain embodiments, the marking operation includes an orientedmarking operation and/or a marking operation including a selectedgeometric configuration (e.g. 3 marks at 120° intervals, 6 marks at 60°intervals, etc.). In certain embodiments, the marking operation includesscoring, punching, perforating, pre-inflating the packer, gouging,grooving, and/or indenting a wellbore surface such as a casing, cementlayer, liner, and/or formation face. In certain embodiments, theinflating operation includes providing a pressure pulse, dropping aball, providing pick-up, set-down, or rotational force to a tubular,providing an electrical signal, and/or pumping a fluid into a wellboreand/or tubular.

As is evident from the figures and text presented above, a variety ofembodiments according to the present disclosure are contemplated.

EXAMPLES Example 1 Inflatable Straddle Packers in Barefoot Openhole

The horizontal portion of the wellbore is completely barefoot, with noliner in the wellbore. The rock or formation face may be marked by adevice to reduce the hoop stress and bias the fracture initiationlocation. Marking the rock face means creating some mechanical defectsuch as a gouge, perforation, groove, indentation etc. For example, astar shaped rotary tool may be pulled along the entire length of thehorizontal lateral in a manner that leaves a continuous line ofindentations into the rock face. Another means of marking the rock faceis to over inflate the packer.

An inflatable straddle packer system can be run into the hole on coiledtubing, or jointed pipe after removing the rock face marking device. Theinflatable straddle packer system can be spaced apart by any length oftubing as desired. Frac ports or openings in the tubing between the twoinflatable packers will allow the injected fracturing fluid to exit thetreatment line fill the isolated portion of the wellbore between thestraddle packers and induce fractures once it reaches the appropriatefracturing pressure. The inflatable packers will have some control valvethat will be activated by a downhole action (pressure pulse, ball drop,electrical signal from battery) to either initiate an inflation sequenceor a deflation sequence. FIG. 3 illustrates this multi-staging example.

The fracturing fluid injection operation can begin once the packers areinflated and the desired portion of the horizontal wellbore is isolated.Two opposing inflatable packers should be self anchoring during fluidinjection into the formation between the two packers. Packer anchorforce can be adjusted as desired. In some embodiments, the opposingpackers exert similar force on the connecting tubing albeit in theopposite direction.

An advantage of the straddle packer system is that one may createfractures at any arbitrary point along the horizontal wellbore in anyorder desired. Toe-to-heel, heel-to-toe, or even alternating toe, heel,middle, near-toe, near-heel, etc. is possible simply by controllingpacker inflation, deflation, and pulling the conveyance tubing in or outof hole to position the straddle packers at the desired depth.

In some embodiments, a single packer does not have a balanced forceoffered by the opposing straddle, and is designed to be self-anchoring.In some embodiments, a single packer has some alternative means ofisolating below the packer. A sand plug in the wellbore is one possiblemeans to achieve this result. A conditioned sand (such as fibers or ahydroscopic water absorbent material) may also be able to accommodatethis. A multimodal slurry may be particularly effective because theparticles will not settle and create a headspace in the horizontalwellbore that compromises zonal isolation. Moreover, adding a materialsuch as fibers, or a hydroscopic, or water absorbent material to Mosaicwill make the subsequent bridge less fluid and thus less able to reopenthe previously created fracture. This example is depicted in FIG. 4.

The inflatable packer and control valve system described in thisscenario can enable Fracture While Drilling (FWD) and Fracture WhileCasing (FWC).

Example 2 Inflatable Straddle Packers in a Perforated Cemented Liner

In this example, the horizontal portion of the wellbore is cased andcemented. The casing can be perforated mechanically after cementing bysome device to bias the fracture initiation location. Perforating thecasing means creating certain holes such as a gouge, perforation,groove, indentation etc. that extends through the casing, but notnecessarily through the cement. For example, a star shaped rotary toolmay be pulled along the entire length of the horizontal lateral in amanner that leaves a continuous line of indentations through the casing.

An inflatable straddle packer system can be run into the hole on coiledtubing, drill pipe, production tubing, or casing after removing therockface marking device. The inflatable packer system could provide aplatform for the mechanical perforator. The inflatable packer affordsconsiderable forces to the casing and if accompanied with a decenttoolkit, could perform that function. FIG. 5 illustrates thismulti-staging example.

The treatment sequence can be operated similarly as described in Example1 above.

Example 3 Inflatable Straddle Packers in Uncemented Liner with ExternalInflatable Casing Packers

This example proposes an improvement on the state-of-the-art uncementedliner systems that are in commercial use today. The commercial systemsmay include mechanical packers (RockSeal) and swellable packers. As aconsequence of being installed in the low side of the horizontalwellbore, the existing commercial systems are not particularly wellsuited for effective isolation toward the high side. Most serviceproviders test the products “on-center” and extrapolate results foroff-center use. Part of the theory of operation is that the packer formsan acceptable barrier albeit not completely pressure tight. In afracturing operation, sand that is in transport across the packer isdehydrated and forms a bridge affecting a good-enough seal. Thegood-enough seal is one that substantially contains most of the volumeof frac fluid so a frac can be placed effectively. This is recognized(and accepted) by the operators because after all, it is better than noisolation at all and it serves the purpose to build the frac.

The use of an inflatable packer may assure good contact everywhere onthe rockface. Moreover, the contact provides good contact pressurenecessary to form a competent seal. This is further assured becauseduring the inflation process, the packer may lift the liner to thecenter of the wellbore, as the hydroforming forces are considerable. Thepacker can be manufactured in lengths suitable for assurance of goodzonal isolation.

The advantages to this approach are that the customer can be assured ofisolation during stimulation treatment and have a better confidenceachieving the treatment design. Further, it can provide zonal isolationduring the productive life of the well. Selective frac sleeves may alsobe used in the productive phase. The inflation valve for this system ismuch straightforward.

Additionally, the following passage details how an inflatable openholezonal isolation system can be used effectively with inflatable packersto achieve rapid multistage fracturing operations. It is recommendedthat the rockface be marked by some device to reduce the hoop stress andbias the fracture initiation location before the liner is run in thehole. Marking the rockface means creating some mechanical defect such asa gouge, perforation, groove, indentation etc. For example, a starshaped rotary tool may be pulled along the entire length of thehorizontal lateral in a manner that leaves a continuous line ofindentations into the rockface.

The liner will have two additional features. One feature is a number ofexternal inflatable packer elements whose purpose is to create a sealbetween the liner basepipe and the rockface. Long inflatable elements ormultiple adjacent packers (virtually without space between the end ofeach packer element) may be installed to reduce the likelihood of alongitudinal fracture from communicating from one isolated zone of thewellbore to another. The individual or clusters of inflatable packerelements will be spaced apart by any distance desired, thus creating aseries of isolated wellbore segments. One can imagine each segmentbetween packers to be at least 10 feet and probably less than 1000 feet.A second feature is that the liner may have either pre-formed holes(slots, holes, etc) or sliding sleeves between each of the spacedinflatable packer elements. These holes/sliding sleeves will permitinjected hydraulic fracturing fluid to exit the interior of the liner,fill the space between the liner and the rockface and create hydraulicfractures at sufficient injection pressure. Sliding sleeves can be openand closed by the normal means (control lines, ball drop, shiftingtool). All the inflatable packer elements will be inflated to createisolated zones along the horizontal wellbore after installation of theliner.

An inflatable straddle packer system can be run into the hole on coiledtubing, drill pipe, production tubing, or casing after inflating theexternal liner inflatable packers. The inflatable straddle packer systemcan be spaced apart by whatever length of tubing is desired, butpreferably, the straddle packers will align with the external linerpackers to create a positive seal. If the liner basepipe is notcontinuously perforated, then the inflatable packers need only seat onunperforated basepipe straddling a sliding sleeve or predrilled hole.Frac ports or openings in the tubing between the two inflatable packerswill allow the injected fracturing fluid to exit the treatment line fillthe isolated portion of the liner, and subsequently the wellbore betweenthe external liner packers and induce fractures once it reaches theappropriate fracturing pressure. The inflatable packers may have somecontrol valve that will be activated by a downhole action (pressurepulse, ball drop, electrical signal from battery) to either initiate aninflation sequence or a deflation sequence.

The fracturing fluid injection operation can begin once the packers areinflated and the desired portion of the horizontal wellbore is isolated.Two opposing inflatable packers can be self-anchoring during fluidinjection into the formation between the two packers. Packer anchorforce can be applied as desired. The opposing packers may exert similarforce on the connecting tubing albeit in the opposite direction. In someembodiment, a single packer is used which may be self-anchoring. FIG. 6illustrates this multi-staging example.

A single packer may also be used with some alternative means ofisolating below the packer. A sand plug in the wellbore is one means ofdoing this. The multimodal slurry may be particularly effective becausethe particles will not settle and create a headspace in the horizontalwellbore that compromises zonal isolation. Moreover, adding a materialsuch as fibers, or a hydroscopic, or water absorbent material to Mosaicwill make the subsequent bridge less fluid and thus less able to reopenthe previously created fracture.

While the disclosure has provided specific and detailed descriptions tovarious embodiments, the same is to be considered as illustrative andnot restrictive in character. Although only a few example embodimentshave been described in detail above, those skilled in the art willreadily appreciate that many modifications are possible in the exampleembodiments without materially departing from this disclosure.Accordingly, all such modifications are intended to be included withinthe scope of this disclosure as defined in the following claims. In theclaims, means-plus-function clauses are intended to cover the structuresdescribed herein as performing the recited function and not onlystructural equivalents, but also equivalent structures. Thus, although anail and a screw may not be structural equivalents in that a nailemploys a cylindrical surface to secure wooden parts together, whereas ascrew employs a helical surface, in the environment of fastening woodenparts, a nail and a screw may be equivalent structures.

Moreover, in reading the claims, it is intended that when words such as“a,” “an,” “at least one,” or “at least one portion” are used there isno intention to limit the claim to only one item unless specificallystated to the contrary in the claim. When the language “at least aportion” and/or “a portion” is used the item can include a portionand/or the entire item unless specifically stated to the contrary. It isthe express intention of the applicant not to invoke 35 U.S.C. §112,paragraph 6 for any limitations of any of the claims herein, except forthose in which the claim expressly uses the words ‘means for’ togetherwith an associated function.

What is claimed is:
 1. A method, comprising: positioning a fractureplacement packer assembly, comprising an inflatable packer positioned onan uphole side of the assembly, in a wellbore at a fracture treatmentposition; inflating the inflatable packer; fracture treating an intervalof a subtteranean formation operationally coupled to the wellbore; andthe method further comprising at least one operation selected from theoperations consisting of: marking the interval before the fracturetreating; wherein the inflating the packer further comprises inflating aself-anchoring packer; fracture treating a second interval after thefirst interval, wherein the second interval comprises a greater measureddepth than the first interval; fracture treating a second interval afterthe first interval, wherein the second interval comprises a smallermeasured depth than the first interval, the method further includingpositioning a sand plug across the first interval before the fracturetreating the second interval; fracture treating a second interval afterthe first interval, wherein the second interval comprises a smallermeasured depth than the first interval, the method further includingpositioning a sand plug across the first interval before the fracturetreating the second interval, wherein the sand plug comprises a highparticulate fraction fluid having a plurality of particle sizemodalities therein; fracture treating a second interval after the firstinterval, wherein the second interval comprises a smaller measured depththan the first interval, the method further including positioning a sandplug across the first interval before the fracture treating the secondinterval, wherein the sand plug comprises a high particulate fractionfluid having a plurality of particle size modalities therein, andremoving an amount of water from the sand plug; performing the fracturetreating with a drill string positioned in the wellbore; performing thefracture treating with an uncemented casing string positioned in thewellbore; interpreting at least one of pressure information, temperatureinformation, and inflation information, determining a wear value for theassembly in response to the information, and providing the wear value toan output device; wherein the marking comprises oriented marking;wherein the marking comprises a selected geometric configuration;wherein the marking comprises at least one operation selected fromscoring, punching, perforating, pre-inflating the packer, gouging,grooving, and indenting; wherein the inflating comprises an operationselected from the operations consisting of providing a pressure pulse,dropping a ball, and providing an electrical signal; providing a linerin the wellbore, positioning a number of external packers between theliner and a wellbore face, wherein each of the external packerscomprises an activatable packer, activating the external packers, andwherein the inflating the inflatable packer comprises running theinflatable packer to a selected position within the liner before theinflating; the method having the “providing a liner” operation, whereinthe selected position comprises a position aligning the inflatablepacker with one of the external packers; and the method having the“providing a liner” operation, wherein the activating the externalpackers comprises at least one operation selected from inflating theexternal packers, swelling the external packers, and mechanicallyactivating the external packers.
 2. A system, comprising: a fractureplacement packer assembly comprising an inflatable packer positioned onan uphole side of the assembly; wherein the inflatable packer isstructured to execute repeated inflation/deflation cycles in response toan inflation/deflation procedure, and wherein the inflatable packer is aself-anchoring packer; and wherein the fracture placement packerassembly is structured to be couplable to a conveyance device.
 3. Thesystem of claim 2, wherein the conveyance device comprises a deviceselected from the devices consisting of: a coiled tubing unit, awellbore tubular; a wellbore casing; and a drill string.
 4. The systemof claim 2, wherein the inflation/deflation procedure is performed usinga device selected from the devices consisting of: a pressure pulsegenerator; an electrical signal generator; and ball activated actuator.5. The system claim 2, further comprising a wellbore having a firstinterval and a second interval, the second interval at a smallermeasured depth than the first interval, the fracture placement packerassembly positioned at a smaller measured depth than the secondinterval, the system further comprising a deviation device positionedacross the first interval.
 6. The system of claim 5, wherein thewellbore at the position of the first interval is one of horizontal andhighly deviated, and wherein the deviation device comprises a sand plug.7. The system of claim 6, wherein the sand plug comprises a highparticulate fraction fluid having a plurality of particle sizemodalities therein.
 8. The system of claim 7, wherein the highparticulate fraction fluid further comprises a water removalconstituent.
 9. The system of claim 8, wherein the water removalconstituent comprises a material selected from the materials consistingof: fibers, a hydroscopic material, a water absorbent material, and acoated material.
 10. The system of claim 2, further comprising awellbore marking tool.
 11. The system of claim 10, wherein the wellboremarking tool comprises a tool selected from the tools consisting of ascoring device, a punching device, a cladding coupled to the inflatablepacker, a gouging device, a grooving device, an indentation device, arotary tool, and a star shaped rotary tool.
 12. A system, comprising: astraddle packer assembly comprising a first inflatable packer positionedon an uphole side of the assembly and a second inflatable packerpositioned on a down hole side of the assembly; wherein each of theinflatable packers are structured to execute repeatedinflation/deflation cycles in response to an inflation/deflationprocedure; wherein the fracture placement packer assembly is structuredto be couplable to a conveyance device; and wherein the straddle packerassembly comprises a spacer element positioned between the first andsecond inflatable packers, the spacer element including a fluidconductance feature and the spacer element structured to maintain theinflatable packers at a specified distance.
 13. The system of claim 12,wherein the conveyance device comprises a device selected from thedevices consisting of: a coiled tubing unit, a wellbore tubular; awellbore casing; and a drill string.
 14. The system of claim 12, whereinthe inflation/deflation procedure is performed using a device selectedfrom the devices consisting of: a pressure pulse generator; anelectrical signal generator; and ball activated actuator.
 15. The systemof claim 12, further comprising a wellbore marking tool.
 16. The systemof claim 15, wherein the wellbore marking tool comprises a tool selectedfrom the tools consisting of a scoring device, a punching device, acladding coupled to at least one of the inflatable packers, a gougingdevice, a grooving device, an indentation device, a rotary tool, and astar shaped rotary tool.
 17. The system of claim 12, further comprisinga liner positioned across a target fracturing zone, and wherein thestraddle packer assembly is positioned such that the first and secondinflatable packers define the target fracturing zone.
 18. The system ofclaim 17, wherein the liner is not cemented, the system furthercomprising two external packers positioned between a formation facecomprising the target fracturing zone, and wherein the first and secondinflatable packers are each positioned at one of the two externalpackers.
 19. The system of claim 18, wherein the two external packerscomprise one of inflatable packers, swellable packers, and mechanicallyactivated packers.
 20. The system of claim 12, wherein the fluidconductance feature comprises at least one feature selected from thefeatures consisting of: slots, ports, openings, and a sliding sleeve.21. The system of claim 12, wherein the specified distance comprises adistance selected from the distance ranges consisting of: five feet toten feet, inclusive; ten feet to thirty feet, inclusive; thirty feet toninety feet, inclusive; and ninety feet to one thousand feet, inclusive.